The world's biggest oil firm is relying on science, technology and, increasingly, its domestic base to insulate it from weaker oil prices

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If ExxonMobil had a formula for weathering the industry's most turbulent era in a generation, it might go something like this: science plus size equals success.

Stubbornly low crude prices have spurred the company's new chairman and chief executive, Darren Woods, to use science and technology to increase margins. Woods, an electrical engineer by training, insists that Exxon is as much a scientific business as it is an oil and gas one. He's accelerating the application of seemingly esoteric research into the field, especially upstream. At the same time, the company is using its unparalleled global footprint and integrated well to petrol pump business model to get the most out of its vast industrial base. It's how Exxon thinks it will weather the turbulence.

"Our job is to compete and succeed in any market, irrespective of conditions or price," Woods said in one of his first speeches after taking the helm. "Participating in each element of the value chain allows us to monitor developments and then anticipate and capture high-value opportunities irrespective of where they occur."

Exxon likes continuity, and the new boss looks like a steady hand. A 25-year veteran of the company, Woods made his name in the refining business which looks askance at the buccaneering mentality of the upstream industry. But his approach is typical Exxon: control of the value chain from the upstream to the downstream. In Exxonspeak it's called "molecule management"; the relentless pursuit of every drop of value in a barrel of oil.

4.4m boe/d - Exxon's output target for 2020, a 300,000-b/d rise

There is nothing new in this formulation. Unwavering commitment to the integrated model has been ExxonMobil dogma going back to Rockefeller's day at Standard Oil, ExxonMobil's forbearer. But it is finding new life with the upstream business under assault from low prices.

Woods points to its growing industrial base along the US Gulf as the latest iteration of Exxon's integrated strategy. It has outlined plans to spend $20bn over 10 years to expand its chemicals, liquefied natural gas and downstream operations in the region. The plan was first unveiled by his predecessor Rex Tillerson in 2013, but in a show of Woods' political chops, he repackaged the announcement earlier this year to win favour with a Trump administration eager to tout early successes of his business-friendly agenda. The new downstream facilities are being built to suck in what ExxonMobil expects will be a flood of new oil, gas and natural gas liquids output from the Permian and Woodford shale plays.

The company has also signed a new joint venture in the Gulf with Energy Transfer Partners, the largest midstream company in the area. The deal gives ExxonMobil extra terminals and pipelines through which to shift barrels to the US Gulf Coast. The arrangement means the company can also increase crude runs at its three Gulf Coast refineries, confident it has the capacity to send out the extra production. Indeed, Exxon is adding processing capacity for an extra 340,000 barrels a day of light crude to reflect the shift in the company's crude slate from heavy imports to light domestic production. Energy Transfer has also been among the largest investors in new crude and NGL export facilities, giving ExxonMobil yet more options.

Integration is especially crucial given the parlous gains on offer in the upstream. In 2016, ExxonMobil earned $7.8bn (from $26.4bn in cash flow) from operations and asset sales. Return on average capital employed, a favoured number for analysts, was 3.9%—way below the average of the past four years before crude prices plummeted.

A closer look shows how the upstream business is financed. ExxonMobil scraped a 0.1% return on the $14.54bn in capital it pumped into that segment, earning just $196m. That compares with the 19.3% earned by the downstream business on $2.46bn capital expenditure and 18.6% booked by the chemical division on $2.2bn invested. In short, Exxon's net income now depends entirely on the latter sectors.

But at least ExxonMobil's still in the black and Woods has kept the faith of investors. The company has increased dividends by 3.5%—the 34th straight year of a rising pay-out. Nor has Woods been forced into the sort of deep capital spending budget cuts seen at the company's rivals. In 2017, he expects to invest $22bn, up by $3bn on 2016, rising to an average $25bn of spending from 2018 through 2020.

Spend, spend, spend

Despite the wafer-thin upstream returns of recent years, ExxonMobil will keep spending to boost reserves. It must—proved reserves fell by 14% in 2016, to around 91bn barrels of oil equivalent. That was mainly the outcome of applying Securities and Exchange Commission rules to some of ExxonMobil's Canadian assets, where the fall in oil prices had wiped some previously booked higher-cost bitumen resources off the balance sheet. (It follows that an increase in oil prices would allow the company to re-book them.)

In terms of production, though, ExxonMobil thinks it can lift output by 300,000 boe/d between now and 2020, up to 4.4m boe/d. Prospects are certainly looking up after years of stagnate output.

In 2017, production will ramp up at the Gorgon liquefied natural gas plant in Western Australia and at the much-delayed Kashagan oilfield in Kazakhstan. Production at Kashagan is currently at 370,000 boe/d and set to rise. Several other projects in which ExxonMobil is involved should start contributing during this year and next, notably in Africa, Russia's Sakhalin oil and gas project, and the Upper Zakum project in Abu Dhabi.

ExxonMobil also has high hopes for its LNG business in Papua New Guinea after wrapping up the purchase in early 2017 of InterOil Corporation.

In Africa, Woods still has faith in Nigeria despite long-term problems with flaring and sabotage, praising ExxonMobil's "long history of success" there. Net liquids production last year averaged only 253,000 b/d, down 15% from 2014. But for all of Nigeria's problems, it remains a haven for oil drillers. In October last year, ExxonMobil said it had found anywhere from 500m to 1bn barrels at its Owowo-3 offshore well, which it plans to develop through existing offshore facilities. On the other side of the continent, Exxon paid $2.8bn cash to buy a stake in an Eni-led LNG development offshore Mozambique.

Despite the wafer-thin upstream returns of recent years, Exxon will keep spending
to boost reserves

Still, the global portfolio is shifting. Woods may be slowly washing ExxonMobil's hands of the North Sea, where, in late March, the group sold much of its Norwegian portfolio to Point Resources, an oil company backed by private equity group HiTechVision. Although Exxon still has interests in 20 other fields in the area, the sale means the loss of 54,000 boe/d. The company has kept mum on its view of the North Sea's long-term prospects, but it's a fair bet that the area won't be seeing much capex in the next few years.

Exxon is far more excited by promising new fields, for instance in Guyana, where it will invest $5bn in its Liza discovery in the Stabroek deep-water block, which is due to pump its first oil in 2020. With a 45% operating interest, Exxon expects the 6.6m-acre Liza to add 100,000 to 120,000 b/d of light oil production, which are profitable even if crude prices stay at $40/b.

Elsewhere at Latin America's frontiers, the company is similarly ambitious about the Vaca Muerta shale play in Argentina, the most promising unconventional area outside North America. In 2016, it started work on a five-well pilot project, and if all goes to plan the company could end up pumping more than $10bn into the Argentine shale over the next two decades.

But the global portfolio offers some thorns too. The company has been embroiled in a 10-year dispute with Venezuela over the 2007 expropriation of its Cerro Negro and La Ceiba oilfields. The company was initially awarded $1.6bn in 2014 in compensation by the International Centre for Settlement of Investment Disputes, though the court partially overturned that ruling in March this year. The legal fight will in all likelihood keep ExxonMobil's lawyers busy for years longer.

An even hotter potato is Russia. So far, Woods has said little about Exxon's future there, apart from a brief expression of his confidence in the vast Sakhalin-1 project with Rosneft and Asian partners on the eastern coast. He's also said other sanctions-hit projects will be re-examined when or if the embargo has been lifted. For now, a potentially huge offshore project agreed with Rosneft in the Kara Sea before the sanctions were applied remains in limbo. And following US air strikes in early April on Bashar al-Assad's regime in Syria (which is backed by Moscow), any hope of a thaw in US-Russia relations looks difficult.

Domestic charge

The US remains a key driver. "Our current focus is on short-cycle, liquids-rich plays, primarily in the Permian Basin, Bakken Formation and Argentina," Woods says. Exxon has significant stakes in nearly every major unconventional play in the US, including 55,000 oil or gas wells. It operates about 80% of them. At presumed prices of $60 a barrel and $3 per 1,000 cubic feet of gas, 24,000 of those wells would give Exxon a return of more than 10%.

Highly acquisitive, Exxon has been expanding these assets, especially in the Permian. A recent $6.6bn deal with Fort Worth's Bass family has added 3.4bn boe of resources in New Mexico's Delaware Basin (part of the Permian). At a stroke, Exxon's resources in the Permian rose to 6bn boe. The company reckons it can now expand its Permian output at 20% a year, from less than 200,000 b/d now, to as much as 0.8m b/d by 2025.

Underlying the business is science and technology. Exxon touts its proprietary Fast Drill technology, for example, which uses advanced physics to boost drilling rates by more than 80% compared with a decade ago. The yields are impressive. In the Permian, Exxon has doubled footage drilled per day in horizontal wells while reducing by 71% the cost of drilling per foot. In other words, it is finding ways to drill faster for less. Cash field expenses have fallen to about $5/b for a 46% reduction over the two years.

The company is also combining physics with data analytics. In 2016, Exxon was so encouraged by trials of a new system of production surveillance at its Serpentina and Jade operations in Equatorial Guinea, and also at Hoover in the Gulf of Mexico, that it now expects to increase production by 7% there and has plans to roll out the system through the upstream portfolio.

This is a long way from the wild-catting days. In February, the company's geoscientists and engineers bolted together a reservoir simulation system that pumped out data "thousands of times faster than typically seen in the industry," Exxon claims. "We expect this development to have a dramatic impact on future reservoir-management capabilities." (Reservoir simulation studies are used in deciding well placement and other vital considerations.)

Another promising recent Exxon technology is "cMIST"—a method of removing water vapour and other impurities from natural gas more cheaply than conventional dehydration towers. Patented in January, it takes 70% less space than towers and is half the weight, making it particularly valuable for offshore platforms, reckons the firm.

Rather than backing away from deep-water developments, it wants technology to make those projects more economically viable. At the Julia tieback in the Gulf of Mexico, the company deployed sub-sea technology that can withstand pressures up to 15,000 pounds per square inch for the first time last year. Julia began production in April 2016 and the technology will speed up production from new wells during 2017. It was one of the few deep-water projects in the world to start up amid the oil price rout, and Exxon did it early and under budget.